Estimation of petrophysical attributes is a very important step needed for reservoir characterization. These attributes depend on the geological environment under which the formation has been deposited. In a nut shell, depositional environment plays an important role in controlling the reservoir properties such as porosity, permeability, water saturation, irreducible water saturation (Swirr etc. In this laboratory study routine and special core analysis were performed on two different reservoirs, one turbidite and the other fluvial deltaic. Emphasis was given to analyze the response of Nuclear Magnetic Resonance (NMR and high pressure Mercury injection (HPMI and to correlate the response with the microstructure/microgeometry of the samples. Based on quantitative mineral analysis the samples from the turbidite formation can be classified as arkosic-lithic and the samples from fluvial deltaic as quartz arenites to subarkosic sands. The porosity ranges from 6% to 19% and 18% to 22% while the permeability ranges from 0.045 md to 30.42 md and 90 md to 500 md for the turbidite and fluvial deltaic formation respectively. NMR spectra were collected on 100% brine saturated and desaturated samples (@100 psi using a bench top commercial resonance instrument. For both groups, NMR estimated porosity values were within +/- 1 porosity unit of gravimetrically determined values. The T2 cutoff, which partitions the pore fluid into movable and bound, was determined using the cutoff BVI (CBVI technique. The average T2 cutoff is 10 msec for the turbidite and 33 msec for the fluvial deltaic samples. The estimated free fluid index (FFI based on 10 mec is approximately 30% to 50 % higher than the FFI calculated from industry recommended T2 cutoff value of 33 msec. The Mean T2 model provides better estimation of the permeability for the turbidite formation while the Free Fluid model provides better estimation for the fluvial deltaic formation. The Swirr for the samples from the turbidite formation ranges from 26% to 40% while for the other it varies from 3% to 15%. Capillary pressure curves generated from the NMR T2 distribution show close agreement with that obtained directly from HPMI. The average surface relaxivity values of the two formations differ by a factor of 2.5 but fall within the values reported in the literature. Such a study helps us to understand the intrinsic behavior of hydrocarbon saturated porous media and can be utilized to extend the potential life of reservoirs that are in the post-plateau stage of production.

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